The present invention relates to borehole measurements and more particularly to a system and method for detecting the presence and estimating the quantity of gaseous and liquid hydrocarbons using nuclear magnetic resonance.
Various methods exist for performing measurements of petrophysical parameters in a geologic formation. Nuclear magnetic resonance (NMR) logging, which is the focus of this invention, is among the best methods that have been developed for a rapid determination of such parameters, which include formation porosity, composition of the formation fluid, the quantity of movable fluid and permeability, among others. NMR measurements are environmentally safe and are essentially unaffected by matrix mineralogy, because NMR signals from the matrix decay too quickly to be detected by the current generation NMR logging tools. Thus, unlike conventional neutron, density, sonic, and resistivity logs, NMR logs provide information only on formation fluids. Importantly, however, NMR tools are capable of directly measuring rock porosity filled with the fluids. Even more important is the unique capability of NMR tools, such as NUMAR Corporation""s MRIL(copyright) tool to distinguish among different fluid types, in particular, clay-bound water, capillary-bound water, movable water, gas, light oil, medium oil, and heavy oil by applying different sets of user-adjusted measurement parameters. (MRIL is a mark of NUMAR Corporation, a Halliburton company). This ability to detect the presence and estimate the volumes of different types of fluids is becoming one of the main concerns in the examination of the petrophysical properties of a geologic formation.
To better appreciate how NMR logging can be used for fluid signal separation and estimating fluid volumes, it is helpful to briefly examine the type of parameters that can be measured using NMR techniques. It is well known that when an assembly of magnetic moments, such as those of hydrogen nuclei, are exposed in a NMR measurement to a static magnetic field they tend to align along the direction of the magnetic field, resulting in bulk magnetization. The rate at which equilibrium is established in such bulk magnetization upon provision of a static magnetic field is characterized by the parameter T1, known as the spin-lattice relaxation time. Another related and frequently used NMR logging parameter is the spin-spin relaxation time T2 (also known as transverse relaxation time), which relaxation is the loss of transverse magnetization due to non-homogeneities varying in time in the local magnetic field over the sensing volume of the logging tool. Both relaxation times provide information about the formation porosity, the composition and quantity of the formation fluid, and others.
Another measurement parameter obtained in NMR logging is the diffusion of fluids in the formation. Generally, diffusion refers to the motion of atoms in a gaseous or liquid state due to their thermal energy. Self-diffusion is inversely related to the viscosity of the fluid, which is a parameter of considerable importance in borehole surveys. In a uniform magnetic field, diffusion has little effect on the decay rate of the measured NMR echoes. In a gradient magnetic field, however, diffusion causes atoms to move from their original positions to new ones, which moves also cause these atoms to acquire different phase shifts compared to atoms that did not move. This effect contributes to a faster rate of relaxation in a gradient magnetic field.
NMR measurements of these and other parameters of the geologic formation can be done using, for example, the centralized MRIL(copyright) tool made by NUMAR Corporation, a Halliburton company, and the sidewall CMR tool made by Schlumberger. The MRIL(copyright) tool is described, for example, in U.S. Pat. No. 4,710,713 to Taicher et al. and in various other publications including: xe2x80x9cSpin Echo Magnetic Resonance Logging: Porosity and Free Fluid Index Determination,xe2x80x9d by Miller, Paltiel, Gillen, Granot and Bouton, SPE 20561, 65th Annual Technical Conference of the SPE, New Orleans, La., Sep. 23-26, 1990; xe2x80x9cImproved Log Quality With a Dual-Frequency Pulsed NMR Tool,xe2x80x9d by Chandler, Drack, Miller and Prammer, SPE 28365, 69th Annual Technical Conference of the SPE, New Orleans, La., Sep. 25-28, 1994. Certain details of the structure and the use of the MRIL(copyright) tool, as well as the interpretation of various measurement parameters are also discussed in U.S. Pat. Nos. 4,717,876; 4,717,877; 4,717,878; 5,212,447; 5,280,243; 5,309,098; 5,412,320; 5,517,115, 5,557,200; 5,696,448 and 5,936,405, all of which are commonly owned by the assignee of the present invention. The Schlumberger CMR tool is described, for example, in U.S. Pat. Nos. 5,055,787 and 5,055,788 to Kleinberg et al. and further in xe2x80x9cNovel NMR Apparatus for Investigating an External Sample,xe2x80x9d by Kleinberg, Sezginer and Griffin, J. Magn. Reson. 97, 466-485, 1992. The content of the above patents and publications is hereby expressly incorporated by reference.
It has been observed that the mechanisms determining the measured values of T1, T2 and diffusion depend on the molecular dynamics of the formation fluids being tested and on the types of fluids present. Thus, in bulk volume liquids, which typically are found in large pores of the formation, molecular dynamics is a function of both molecular size and inter-molecular interactions, which are different for each fluid. Water, gas and different types of oil each have different T1, T2 and diffusivity values. On the other hand, molecular dynamics in a heterogeneous media, such as a porous solid that contains liquid in its pores, differs significantly from the dynamics of the bulk liquid, and generally depends on the mechanism of interaction between the liquid and the pores of the solid media. It will thus be appreciated that a correct interpretation of the measured signals can provide valuable information relating to the types of fluids involved, the structure of the formation and other well-logging parameters of interest.
If the only fluid in the formation is brine, a Carr-Purcell-Meiboom-Gill (CPMG) pulse sequence with a short inter-echo spacing (Te) and a long wait-time (Tw) can be applied for porosity determination and identification of capillary-bound and free water volumes. Total porosity logging methods are available to improve the quality of data used for determining pore volumes occupied by clay-bound and/or capillary-bound water. (See, for example, Prammer, M. G., et al.: xe2x80x9cMeasurements of Clay-Bound Water and Total Porosity by Magnetic Resonance Logging,xe2x80x9d paper SPE 36522 presented at the 1996 SPE Annual Technical Conference and Exhibition, Denver, October 6-9). However, if hydrocarbons, such as formation oil and/or gas or filtrate from oil-based mud, coexist with brine, porosity determination and fluid typing (identification and quantification) with NMR becomes more difficult.
Additional difficulties arise from the fact that NMR measurements impose limitations on the logging speed. For example, it is known in the art that for porosity determination all stimulated fluid protons should be sampled at full polarization. Therefore, a long wait time Tw is required to completely detect the magnetization from protons in slow T1 processes. For gas and light oil under typical formation conditions of temperature and pressure (100-300xc2x0 F. and 2,000-10,000 psi), T1 values of a few seconds occur at low-frequency (1- to 2-MHz) NMR. Wait times Tw of at least 10 seconds will capture nearly all the total proton magnetization arising from the individual T1 recovery rates encountered in petroleum logging. Such long wait times, combined with acceptable depth sampling, restrict the logging speed and reduce wellsite efficiency. One approach addressing this problem is the application of prepolarization and multislice (multifrequency) acquisitions implemented in the Magnetic Resonance Imaging Logging(trademark) MRIL-Prime tool. See Prammer, M. G., et al.: xe2x80x9cTheory and Operation of a New Multi-Volume NMR Logging System,xe2x80x9d paper DD presented at the 40th Annual SPWLA Logging Symposium, Oslo, Norway, May 30-Jun. 3, 1999. Still, it is believed that the capabilities of the MRIL tool have not yet been fully utilized.
Turning to the problem of fluid typing by NMR, it is known that it relies on contrasts of characteristic parameters of the fluids, such as T1, T2, and diffusivity. Two or more CPMG data sets, which may not be completely polarized, are usually acquired to exploit parameter contrasts among the expected fluids. Using NMR logging to determine reservoir porosity occupied by gas or light oil currently requires data simultaneously acquired from at least two CPMG sequences having different wait-times. Examples of this method are disclosed in U.S. Pat. No. 5,936,405 to the assignee of the present application. The content of this patent is incorporated herein by reference for all purposes.
Dual-wait-time and dual-frequency methods have been applied to determine gas volumes in both clean and shaley sand formations. It is known that the success of the application depends primarily on two factors. First, adequate signal-to-noise levels in an echo train difference has to be maintained so that the gas-filled porosity and its transverse relaxation time T2 can be accurately characterized. Second, methods must be available to reliably estimate the longitudinal relaxation time T1 of the hydrocarbon phase needed to apply a necessary amplitude correction to the apparent hydrocarbon-filled porosity. It is clear that data acquisition and processing methods that address these two factors with success are highly desirable.
NMR technology has been successfully applied to distinguish fluids, and significant progress has been made in determining porosity in mixed-fluid situations. The reader is directed for details to the disclosure of U.S. provisional patent application Ser. No. 60/106,259, filed Oct. 30, 1998 to the assignee of the present application. The content of this application is incorporated herein by reference for all purposes. Still, quantitative analysis to determine actual hydrocarbon volumes present in the instrument""s measurement space remains difficult because polarization corrections applied to apparent hydrocarbon volumes rely on accurate knowledge of the hydrocarbon T1.
Several researchers have acknowledged the importance of T1 in quantitative fluid typing. Obtaining enough saturation-recovery data points to derive an accurate and precise T1 distribution of a fluid at acceptable logging speeds and vertical resolution is difficult or nearly impossible. Consequently, most quantitative analyses rely on T1 values computed from correlation functions or by the application of assumptions to measured values. One disadvantage of such methods is that formation parameters, such as temperature, pressure, and fluid viscosity, may not be accurately known. In addition, attention must be directed to the ranges for which the correlation functions are valid. Prior art methods of deriving T1 involve either dual Tw""s with one inter echo spacing Te or dual Tw""s with multiple Te""s. See Akkurt, R., Prammer, M. G., and Moore, M. A.: xe2x80x9cSelection of Optimal Acquisition Parameters for MRIL Logs,xe2x80x9d The Log Analyst (November-December 1996) 43; and Chen, S., et al.: xe2x80x9cEstimation of Hydrocarbon Viscosity with Multiple TE Dual Wait-Time MRIL Logs,xe2x80x9d paper SPE 49009 presented at the 1998 SPE Annual Technical Conference and Exhibition, New Orleans, September 27-30. Both methods referenced above assume that oil (or unpolarized brine) T2 signals are totally separated from brine T2 signals, which assumption is sometimes incorrect. Methods for obtaining gas T1 values from NMR logs have not been previously developed.
In addition to being an important parameter for correcting apparent volumes of fluids for under-polarization, T1 computations play an important role in distinguishing one fluid from another. For example, it is well known that gas and light oil have large T1 values, and thus can be separated from brine, which typically has lower values for T1. Furthermore, fluid viscosity and self-diffusion coefficient D that can be obtained from a known T1 value can be used to separate gas from other fluids. Thus, large values for both T1 and D reliably indicate the presence of gas or light oil in a formation. Fluid viscosity can also be used in grouping liquids. Various additional contrast mechanisms are known in the art and are described, for example, in the above-referenced U.S. provisional application No. 60/106,259, filed Oct. 30, 1998 to the assignee of the present application. Because T1 relaxation times are not influenced by interactions between magnetic gradients and molecular diffusion, fluid viscosities obtained from measured T1""s are believed to be superior to other methods whenever a gradient-field logging tool is used or an internal magnetic gradient from the formation is present.
In view of the shortcomings of the prior art briefly outlined above, it is apparent that there is a need for a method and system that can take full advantage of the flexibility provided by current-generation NMR tools to enable the accurate calculation of T1 and T2 parameters for different fluids over the range of geologically meaningful values. This calculation in turn will enable reliable detection of the presence of gaseous and liquid hydrocarbons and estimation of their quantities.
Accordingly, it is an object of the present invention to provide a method and apparatus using nuclear magnetic resonance (NMR) techniques that obviate problems associated with the prior art.
In particular, a new triple-wait-time, multi-frequency acquisition method is disclosed and successfully tested. The method takes advantage of the multi-frequency operation of modern NMR logging tools to improve the signal-to-noise ratio of the received signals at high logging speeds. Further, the acquisition method enables accurate estimation of volumes for hydrocarbon and/or free water in addition to traditional clay-bound and capillary-bound water volumes.
The new acquisition method uses optimized wait times to obtain better signal-to-noise ratios in echo train differential signals at faster logging speeds and acceptable vertical resolution. In turn, these signals can be used to determine formation fluid volumes, as well as estimates of hydrocarbon T1. Experiments performed on a mixture of dodecane (C12H26) and doped water, C12H26 and brine in a sandstone core, and fresh water produced fluid volumes with absolute errors of less than 1.5% for echo train differences with a signal-to-noise ratio larger than 4:1.
In another aspect, the present invention provides a data processing method that enables the accurate determination of both T2 and T1 parameters of hydrocarbons based on the use of at least two difference NMR signals obtained at different wait times. The data acquisition and processing method of the present invention enable the determination of gas- and light-oil-filled porosity over a broad range of reservoir conditions. In another aspect, the present invention provides a decision mechanism to help in the selection of optimum acquisition parameters for logging applications.
In particular, in accordance with the present invention is provided a (NMR) data acquisition method, comprising: providing a first set of CPMG pulses associated with a first relatively short recovery time TWS1; providing a second set of CPMG pulses associated with a second relatively short recovery time TWS2, where TWS2 is longer than TWS1; providing a third set of CPMG pulses associated with a relatively long recovery time TWL1; receiving NMR echo signals from a population of particles in response to the first, second and third sets of CPMG pulses; and processing the received NMR echo signals to provide a data representation associated with the longitudinal relaxation time constant T1 of the population of particles.
In specific embodiments, the steps of providing the first, second and third sets of CPMG pulses are interleaved in time and/or are acquired in different sensitive volumes. In these embodiments, the steps of providing the first, second and third sets of CPMG pulses are performed using a multi-frequency NMR logging tool. In different specific embodiments CPMG pulses associated with different recovery times may have either same or different operating frequencies. In a preferred embodiment, the first and second short recovery times TWS1 and TWS2 are selected long enough to substantially polarize a water phase component in the population of particles, or in such manner that water-phase contribution is substantially canceled in a difference signal formed by subtracting NMR signals corresponding to a relatively short recovery time from NMR signals corresponding to the relatively long recovery time TWL1.
In another aspect, in accordance with the present invention is provided a method for conducting NMR logging measurements, comprising: providing a data acquisition sequence comprising at least two sets of CPMG pulses having relatively short recovery times TWS1 and TWS2, respectively, and at least one set of CPMG pulses having relatively long recovery time TWL1; receiving NMR echo signals from a population of particles in a geologic formation in response to the provided sets of CPMG pulses; processing the received NMR echo signals to determine a first and a second apparent volumes for at least one hydrocarbon fluid phase of the geologic formation, said first apparent volume being determined from a data representation associated with signals having short recovery time TWS1, and the second apparent volume being determined from a data representation associated with signals having short recovery time TWS2; providing a data representation associated with the longitudinal relaxation time constant T1 of said at least one hydrocarbon fluid phase based on the determined first and second apparent volumes.
In a specific embodiment processing the received NMR echo signals comprises: forming a first difference signal Edif1 by subtracting NMR signals having relatively short recovery time TWS1 from NMR echo signals having relatively long recovery time TWL; computing T2 distribution of the first difference signal Edif1; and determining a value for the T2 relaxation time of said at least one hydrocarbon phase. In another embodiment, the method further comprises forming a second difference signal Edif2 by subtracting NMR signals having relatively short recovery time TWS2 from NMR echo signals having relatively long recovery time TWL. In a preferred embodiment, the method further comprises the step of computing the total porosity of the formation xcfx86t from the total apparent porosity xcfx86ta and apparent volume corrections computed based on the provided data representation associated with the longitudinal time constant(s) T1 of the fluid phases.
In another aspect, the present invention is a method of operating a multi-volume NMR logging tool, comprising: (a) acquiring a first NMR echo train or sets of echo trains in a first sensitive volume of the tool, said first echo train(s) carrying information about NMR signals with recovery time TWS1; (b) acquiring a second NMR echo train or sets of echo trains in a second sensitive volume of the tool, said second echo train(s) carrying information about NMR signals having recovery time TWL; (c) acquiring a third NMR echo train or sets of echo trains, said third echo train(s) carrying information about NMR signals with recovery time TWS2; (d) computing values for the transverse relaxation time T2 and apparent volume for at least one hydrocarbon fluid phase based on the acquired NMR echo trains; and (e) providing a data representation associated with the longitudinal relaxation time constant T1 of said at least one hydrocarbon fluid phase based on the determined first and second apparent volumes.
In another aspect, the present invention is a NMR data processing method for use in borehole logging, comprising: selecting values for a second relatively short recovery time TWS2 using a known functional relationship based on estimates of: (a) a first relatively short recovery time TWS1 needed to polarize water signals in a geologic formation surrounding the borehole; and (b) expected T1 values for hydrocarbon fluid phases in the geologic formation surrounding the borehole; providing a data acquisition sequence comprising at least two sets of CPMG pulses having said relatively short recovery times TWS1 and TWS2, respectively, and at least one set of CPMG pulses having relatively long recovery time TWL; processing NMR echo signals received in response to the data acquisition sequence to provide an estimate of the true values for the longitudinal relaxation time constant T1 of hydrocarbon fluid phases in the geologic formation, wherein the accuracy of the estimates of the T1 constant is controlled in the step of selecting.